Instantaneous Shut-in Pressure Research Articles

First Successful Wireline Stress Testing in a Gas Hydrate Reservoir in the Hyuganada Sea, Japan

This study presents a stress testing operation conducted using a wireline formation tester in a newly discovered gas hydrate prospect located offshore in Japan. The campaign, which spanned from December 2021 to January 2022, involved drilling a well using logging-while-drilling technology. Subsequently, wireline formation testing and stress testing were successfully conducted at three different depths within a gas hydrate-concentrated zone. The testing was accomplished in a single riserless descent, with the primary goal of obtaining crucial data such as mobility, formation pressure, and fracture gradient for one of the prospects. This operation marked the first stress testing job performed with dual packers in an open water and deepwater environment specifically for gas hydrate reservoirs. The study also provides a comprehensive interpretation of the data gathered during the operation. Moreover, it evaluates various properties such as formation mobility, formation pressure, initial breakdown pressure, closure pressure, fracture propagation pressure, and instantaneous shut-in pressure.

Estimation of the Fracturing Parameters and Reservoir Permeability Using Diagnostic Fracturing Injection Test

The term "tight reservoir" is commonly used to refer to reservoirs with low permeability. Tight oil reservoirs have caused worry owing to its considerable influence upon oil output throughout the petroleum sector. As a result of its low permeability, producing from tight reservoirs presents numerous challenges. Because of their low permeability, producing from tight reservoirs is faced with a variety of difficulties. The research aim is to performing hydraulic fracturing treatment in single vertical well in order to study the possibility of fracking in the Saady reservoir. Iraq's Halfaya oil field's Saady B reservoir is the most important tight reservoir. The diagnostic fracture injection test is determined for HF55using GOHFER software. Models for petrophysics and geology were calibrated using the diagnostic fracture injection test results after the petrophysical and geomechanical parameters of the rock have been determined. The HF55 vertical well, which penetrates the Saady reservoir, has well logs that have been used to evaluate the petrophysical and geomechanical parameters. These estimates have been supported by findings from the diagnostic fracture injection test through the utilization of standard equations and correlations. The findings of the diagnostic fracture injection test, often known as the diagnostic fracture injection test, are very compatible with the findings of the well logs. The diagnostic fracture injection test pre-falloff test event was examined to determine the instantaneous shut-in pressure and fracture gradient. In the meantime, Closure pressure, process zone stress, fracturing fluid efficiency, closure gradient, critical fissure opening pressure, storage correction factor, permeability, and pressure-dependent leak-off coefficient were all determined using the G function on plot. With the help of a specific software, the petrophysical and geomechanical properties of a single vertical well [HF55] was found. Saady B reservoir's upper and lower sections, along with it are therefore predicted to have the full range of petrophysical and geomechanical features. With the use of DFIT analysis, these features serve as the foundation for developing fracturing models.

Integrated microseismic and geomechanical analysis of hydraulic fracturing induced fault reactivation: a case study in Sichuan Basin, Southwest China

Because of the special geographical location adjacent to the Tibetan Plateau, the geological setting of the Sichuan Basin is very complex, which brings a great challenge to shale gas development. In this study, we conducted an integrated microseismic and geomechanical analysis on a refracturing well in the Sichuan Basin. We observed that casing deformation occurred in the area of fault reactivation. However, the reactivation of pre-existing faults does not always cause casing deformation. In addition, a cluster of high-magnitude microseismic events will be triggered during the fault reactivation, which is also helpful to recognize the reactivated faults. Furthermore, according to the definition of b-value in the Gutenberg–Richter law, a group of high-magnitude microseismic events usually shows a low b-value and vice versa. Based on the analysis of treatment data and microseismicity, we found that there is a positive relationship between b-value and instantaneous shut-in pressure (ISIP): lower b-value represents lower ISIP. The investigation of the stress shadow effect based on the theoretical solution of a plane strain fracture is also convincing to prove the relationship between b-value and ISIP. Therefore, a significant relationship between hydraulic fracturing, microseismicity, and fault reactivation is established. Importantly, some useful implications of this relationship could be utilized for early warning of fault reactivation (probably casing deformation) and optimization of refracturing design for unconventional shale plays.

Technology Focus: History Matching and Forecasting (April 2023)

_ This year’s history matching and forecasting selections cover topics that include performance prediction of a polymerflood pilot in a heavy oil reservoir, multivariate characterization and modeling of a paleo zone, and multiwell pressure history matching in an unconventional reservoir. The authors of paper SPE 206247 developed a history-matched reservoir simulation model for a polymerflood pilot to enhance heavy oil recovery on the Alaska North Slope. According to the authors, the viscous fingering effect in the reservoir during waterflooding and the restoration of injection conformance during polymerflooding were effectively represented. Using the history-matched model, studies were conducted to investigate the oil-recovery performance under different development strategies, with consideration for sensitivity to polymer parameter uncertainties. In paper IPTC 22034, the authors present an approach that incorporates characterization of paleo zones, parameterization of paleo-zone conductivity, and application of flow profiles as a guide in the history-matching study of a conceptual reservoir simulation model under reservoir uncertainty. The authors conclude that the modeled paleo zone acts as a baffle inducing a partial confinement of the injectors. Solving a global optimization problem to minimize the mismatch between the instantaneous shut-in pressure and treatment pressures measured in the field and simulated by the model, for all stages and all wells, is the subject of paper SPE 204162. According to the authors, the technique reduces overfitting by minimizing the number of variables used for history matching, by increasing the number of wells and stages that are simultaneously matched, and by reproducing the dominant behavior of all stages instead of capturing the detailed behavior of specific stages. Recommended additional reading SPE 210224 Rate-Transient-Analysis-Assisted Numerical History Matching and Co-Optimization of CO2 Storage and Huff ’n’ Puff Performance for a Near-Critical Gas Condensate Shale Well by Hamidreza Hamdi, University of Calgary, et al. URTeC 3724391 Fractional Dimension Rate-Transient Analysis in Unconventional Wells: Application in Multiphase Analysis, History Matching, Forecasting, and Interference Evaluation by Behnam Zanganeh, Chevron, et al. SPE 200908 Application of an Integrated Ensemble-Based History-Matching Approach—An Offshore Field Case Study by Usman Aslam, Emerson, et al.

Location estimation of subsurface fluid-filled fractures: Cepstral predominant peak analysis and numerical study

In various subsurface resource development or fluid piping transportation problems, subsurface fluid-filled fractures often appear. Fracture location determination has always been critical in the related fields. Acoustic wave reflection at the junction and boundary in the pipeline can carry information about the property of the system. By using the accompanying acoustic wave information combined with the water hammer effect, the location of subsurface fractures can be estimated. A numerical fluid flow model for instantaneous shut-in is presented based on the water hammer effect. Fluid penetration effects, wellbore storage effect, and fluid inertial effect are considered. A method for determining the locations of subsurface fractures using cepstral predominant peak (CPP) is first proposed. By cepstral, we mean the inverse Fourier transform of the logarithm of the estimated signal spectrum. Also, the relationship between instantaneous shut-in pressure and cepstrum response is investigated in detail. To improve the robustness, CPP analysis based on Kaiser windowed cepstrum is used to identify the impulse period of fracture. Compared with the original cepstrum, Kaiser windowed cepstrum has the better performance for CPP analysis. The proposed flow model is impactful as it can provide pressure data with known fracture locations. Meanwhile, the data can be used to optimize and examine the performance of CPP analysis with Kaiser windowed cepstrum. A field experiment is conducted to validate the analysis about the acoustic wave in a pipeline system with fractures. By installing a high-frequency pressure monitoring device at the pump, the actual instantaneous shut-in pressure for an oil well is obtained. The experiment results show that the CPP analysis can obtain the fracture location efficiently and accurately, which can provide insights for engineering practices.

Pressure Interpretations in Acid Fracturing Treatments

SummaryAcid fracturing is a preferred method of stimulating low-permeability limestone formations throughout the world. The treatment consists of pumping alternating cycles of viscous pad and acid to promote differential etching, thereby creating a conductive acid-etched fracture.Acid type, pad and acid volumes, and the injection rates in the designed pump schedule are based on treatment objectives, rock types, and in-situ conditions such as temperatures, in-situ stress, proximity to water-bearing layers, and others. During the acid fracturing treatment, the acid-rock interaction is often marked by signature pressure responses, that are a combined outcome of acid reaction kinetics, responses to changes in fluid viscosity and densities, fluid-frictional drop in narrow hydraulic fractures, and other such parameters. This paper focuses on interpretation of bottomhole pressures (BHPs) during acid fracturing treatment to separate these individual effects and determine the effectiveness of the treatment.Unlike propped fracturing treatments where most fracturing treatments result in net pressure gain, acid fracturing treatments seldom result in net pressure increase at the end of the treatment because the in-situ stresses are generally relieved during the rock dissolution and fracture width creation process that results from acid-mineral reactions. Not only is the extent of stress relief evident from the difference in the start and the end of the treatment instantaneous shut-in pressures, the loss of stresses is also apparent during the treatment itself, especially in jobs where the treatment data are constantly monitored and evaluated in real time. The study reveals that the changes in pressure responses with the onset of acid in the formation can be successfully used to determine the effectiveness of treatment design and can aid in carrying out informed changes during the treatment. Better understanding of these responses can also lead to more effective treatment designs for future jobs.The interpretation developed in the study can be applied to most of the acid fracturing treatments that are pumped worldwide.

Estimating the Least Principal Stress in a Granitic Rock Mass: Systematic Mini-Frac Tests and Elaborated Pressure Transient Analysis.

The hydraulic fracturing technique (also termed mini-frac test) is commonly used to estimate the in situ stress field. We recently conducted a mini-frac stress measurement campaign in the newly-established Bedretto Underground Laboratory (BedrettoLab) in the Swiss Alps. Four vertical boreholes, dedicated for stress characterization of the granitic rock mass, hosted a total of 19 mini-frac test intervals. Systematic pressure transient analysis was performed to carefully estimate the magnitude of the least principal stress (S_mathrm {3}). We compared five different methods (inflection point, bilinear pressure decay rate, tangent, fracture compliance, and jacking pressure) to identify an adequate approach best suited for our test scale and the host rock mass. We found that the methods used to determine the fracture closure pressure underestimate the magnitude of S_mathrm {3}, presumably due to the rapid closure of the hydraulic fracture after shut-in. The most consistent results were found using the inflection point and bilinear pressure decay rate method, which both determine the (instantaneous) shut-in pressure as the proxy for the S_mathrm {3} magnitude. The determined shut-in pressure, or S_mathrm {3} magnitude, is 14.6pm 1.4 MPa from the inflection point method. This allowed us to further estimate the stress environment around the BedrettoLab, which is transitional between normal and strike-slip faulting. The measured local pore pressures from extended shut-in periods are between 2.0 and 5.6 MPa, significantly below hydrostatic. A combination of drainage, cooling, and the excavation damage zone of the tunnel may have significantly perturbed the in situ stress field in the vicinity of the BedrettoLab.

Petrophysical/geophysical approaches to identify ISIP variability in the Eagle Ford shale

Understanding geomechanical properties is essential for an optimal completion strategy that ensures commercial productivity in shale reservoirs with ultra-low permeability. This study provides details to identify the variability of Instantaneous Shut-In Pressure (ISIP) in multidisciplinary approaches using petrophysical and geophysical data. ISIP is one of the input data required for well completion design. Operators commonly ignore the variability of ISIP and use uniform geomechanical assumptions due to cost and time constraints. In the case study, the variability of ISIP was observed up to 30 % in a single horizontal well, which could lower the efficiency of hydraulic fracturing with uniform geomechanical assumptions along a horizontal well trajectory. We propose practical approaches to identify the variability of ISIP from a case study in the Eagle Ford shale. MWD (Measurement While Drilling) Gamma Ray log, which is commonly acquired for a geosteering purpose, was utilized to prove its correlation with actual ISIP data gained at frac-stages in horizontal production wells. Correlation between ISIP and microseismic data was analyzed to identify the integrated relationship among the variability of Gamma Ray, ISIP, and hydraulically-induced fracture. In addition, practical approaches using a series of seismic inversion and attribute data were proposed to help identify geological variabilities affecting ISIP. This study was designed to provide operators hands-on approaches to capturing the variability of ISIP under limited data accessibility. We suggest multifunctional ways using the basic datasets commonly available at field sites. It can be applied to mitigate risks concerning well planning, drilling, and completion design in where operators face frequent challenges from geomechanical heterogeneity in global shale plays.

Effects of Overpressure on Mechanical Properties of Unconventional Shale Reservoirs through Novel Use of a Sonic Overpressure Indicator

Summary Overpressure is a common feature among productive unconventional shale reservoirs, such as the Bone Spring (BSPG) and Wolfcamp (WFMP) Formations of the Delaware Basin (DB) of west Texas and southeastern New Mexico, and is thought to be a strong driver of well productivity. Compared with conventional reservoirs and shales in normal pressured conditions, the effects of overpressure on the mechanical properties of shales is not well understood. Here we present an analysis of overpressure in clay-bearing siliciclastic facies of the BSPG and WFMP Formations of the DB and implications for mechanical properties of the reservoir. Estimation of the effects of overpressure on mechanical properties of unconventional shale reservoirs is determined through use of the sonic overpressure indicator (SOPI). The method requires log model results that accurately characterize variations in lithology and porosity for the formations of interest. The SOPI (ΔT/ΔTN)2, where ΔT is the measured compressional sonic transit time, and ΔTN is the forward-modeled result for normally pressured conditions, can be used with elastic moduli and their interrelationships to compare estimates of mechanical properties including Poisson’s ratio ν, the Biot or effective stress coefficient α, and Young’s modulus E, in normal and overpressured conditions. Results presented here are broadly applicable to overpressured unconventional reservoirs that contain significant clay volume (>0.1 v/v) and exhibit low porosity (<0.08 v/v), comparable to that of siliciclastic-rich facies of the WFMP Formation. To account for increased VP/VS ratio, we regard overpressurization of shaly facies as an irreversible thermodynamic process that transforms a normally pressured siliciclastic system. At stress below the yield point, which is taken as the limit of normal pressure, the system responds elastically to stress; beyond this point, during overpressurization, the system responds as an elastic/plastic medium with strain hardening. We regard elastic moduli as descriptive of mechanical energy stored in this system. This perspective enables Poisson’s ratio for the overpressured system νOP to be computed from an estimate of the normally pressured system νN using (ΔT/ΔTN)2. Overpressure also results in a limited increase of the Biot or effective stress coefficient α. Moreover, recognition that overpressure results in a decrease of Young’s modulus, that is, EOP/EN < 1, provides a means of estimating the amount of strain energy stored by the formation due to overpressurization. We believe that when exposed to lower pressures by wellbore construction, this strain energy stored in overpressured unconventional reservoirs drives creep, which affects interpretations made using geomechanical models. We have developed and tested computational models based on biaxial or plane strain for vertical wells and uniaxial strain for horizontal wells that describe how creep likely affects estimation of minimum horizontal stress Shmin and pore pressure from instantaneous shut-in-pressure (ISIP) measurements. Thus, for overpressured unconventional reservoirs, ISIP determinations differ from tectonic Shmin by an amount related to ν and EOP/EN.

Variation of induced stress field during hydraulic fracture closure and its influence on subsequent fracture

After the completion of multi-stage fracturing operation, the fluid pressure in artificial fracture network continues to decrease, resulting in the closure of fracture and the variation of local induced stress field. This process can also lead to the variation of fracture propagation pattern in the subsequent fracturing stages. To better guide fracturing design, the time effect of stress field was researched. A numerical method was used to solve the induced stress around a propped fracture, and analyze the influence of formation properties and treatment parameters on its change. Then, the characteristics of stress field with different closure times and its influence on subsequent fracture were investigated. Finally, the evolution of the stress field in two stimulated wells was analyzed using the instantaneous shut-in pressure. The results show that the original horizontal stress difference, fluid pressure in fracture, fracture length, fracture angle, and amount of proppant have significant effects on the variation of induced stress field. The stress field of formation with undeveloped natural fractures decreases quickly with the rapid closure of hydraulic fractures due to the rapid drop in fluid pressure, but the stress field remains relatively constant after the fracture is fully propped. For formation with developed low angle natural fractures, the stimulated stage promotes subsequent fracture propagation and improves fracturing efficiency. The fluid pressure declined slowly and is non-uniformly distributed during the closure of the complex fracture network. Therefore, the magnitude and scope of the induced stress vary unevenly with the closure time, and there is a reasonable treatment time to form complex fractures during hydraulic fracturing. This study provides new insights into fracturing operation.

Frac-n-Flow Testing to Screen Brittle Fracture Stages in Wolfcamp Formation, Permian Basin, USA

A new technique, fracturing-and-flowing (frac-n-flow) testing, is introduced for horizontal drilling and multistage hydraulic fracturing (HDMHF) practitioners to check if the next stage would be a brittle fracture using the instantaneous shut-in pressure (ISIP) from the current stage. It was developed to reduce the number of not-flowing clusters in HDMHF treatments due to stress shadows in the development of tight oil reserves in Wolfcamp, Permian Basin, USA, and other similar fields. Preliminary frac-n-flow testing results show that a medium (200–1000 psi) increase in confining pressure under representative field in-situ stresses can transfer Indiana limestone from brittle fracturing to semi-ductile failing. Consequently, folds of increase (FOI) of matrix permeability vary from +13 (i.e., increase by 1300%) to −0.39 (i.e., decrease by 39%). Limestone is one of the major lithological components in Wolfcamp formation. Field ISIP data of two HDMHF wells in Wolfcamp formation show that the maximum stress shadows are +1297 psi and +1716 psi, respectively. These stress shadows might have transferred the fracturing process from brittle to semi-ductile, converting the corresponding stages from being stimulated and conductive (fracturing-n-flowing) to being damaged and not-flowing (failing-n-not-flowing). Field completion reports of the two wells confirmed that screen-out and other interruptions of operation occurred in these high stress shadowed stages.

Work Flow History Matches Numerical Simulation Models of Fractured Shale Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199149, “Rate-Transient-Analysis-Assisted History Matching With a Combined Hydraulic Fracturing and Reservoir Simulator,” by Garrett Fowler, SPE, and Mark McClure, SPE, ResFrac, and Jeff Allen, Recoil Resources, prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, originally scheduled to be held in Bogota, Colombia, 17–19 March. The paper has not been peer reviewed. This paper presents a step-by-step work flow to facilitate history matching numerical simulation models of hydraulically fractured shale wells. Sensitivity analysis simulations are performed with a coupled hydraulic fracturing, geomechanics, and reservoir simulator. The results are used to develop what the authors term “motifs” that inform the history-matching process. Using intuition from these simulations, history matching can be expedited by changing matrix permeability, fracture conductivity, matrix-pressure-dependent permeability, boundary effects, and relative permeability. Introduction This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199149, “Rate-Transient-Analysis-Assisted History Matching With a Combined Hydraulic Fracturing and Reservoir Simulator,” by Garrett Fowler, SPE, and Mark McClure, SPE, ResFrac, and Jeff Allen, Recoil Resources, prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, originally scheduled to be held in Bogota, Colombia, 17-19 March. The paper has not been peer reviewed. This paper presents a step-by-step work flow to facilitate history matching numerical simulation models of hydraulically fractured shale wells. Sensitivity analysis simulations are performed with a coupled hydraulic fracturing, geomechanics, and reservoir simulator. The results are used to develop what the authors term “motifs” that inform the history-matching process. Using intuition from these simulations, history matching can be expedited by changing matrix permeability, fracture conductivity, matrix-pressure-dependent permeability, boundary effects, and relative permeability. Introduction The concept of rate transient analysis (RTA) involves the use of rate and pressure trends of producing wells to estimate properties such as permeability and fracture surface area. While very useful, RTA is an analytical technique and has commensurate limitations. In the complete paper, different RTA motifs are generated using a simulator. Insights from these motif simulations are used to modify simulation parameters to expediate and inform the history- matching process. The simulation history-matching work flow presented includes the following steps: 1 - Set up a simulation model with geologic properties, wellbore and completion designs, and fracturing and production schedules 2 - Run an initial model 3 - Tune the fracture geometries (height and length) to heuristic data: microseismic, frac-hit data, distributed acoustic sensing, or other diagnostics 4 - Match instantaneous shut-in pressure (ISIP) and wellhead pressure (WHP) during injection 5 - Make RTA plots of the real and simulated production data 6 - Use the motifs presented in the paper to identify possible production mechanisms in the real data 7 - Adjust history-matching parameters in the simulation model based on the intuition gained from RTA of the real data 8 -Iterate Steps 5 through 7 to obtain a match in RTA trends 9 - Modify relative permeabilities as necessary to obtain correct oil, water, and gas proportions In this study, the authors used a commercial simulator that fully integrates hydraulic fracturing, wellbore, and reservoir simulation into a single modeling code. Matching Fracturing Data The complete paper focuses on matching production data, assisted by RTA, not specifically on the matching of fracturing data such as injection pressure and fracture geometry (Steps 3 and 4). Nevertheless, for completeness, these steps are very briefly summarized in this section. Effective fracture toughness is the most-important factor in determining fracture length. Field diagnostics suggest considerable variability in effective fracture toughness and fracture length. Typical half-lengths are between 500 and 2,000 ft. Laboratory-derived values of fracture toughness yield longer fractures (propagation of 2,000 ft or more from the wellbore). Significantly larger values of fracture toughness are needed to explain the shorter fracture length and higher net pressure values that are often observed. The authors use a scale- dependent fracture-toughness parameter to increase toughness as the fracture grows. This allows the simulator to match injection pressure data while simultaneously limiting fracture length. This scale-dependent toughness scaling parameter is the most-important parameter in determining fracture size.

Azimuthal P-P prestack amplitudes in the presence of oil-filled aligned porosity (fracture porosity)

A 3D P-P high-fold full-azimuth full-offset reflection survey was acquired and processed to characterize a naturally fractured carbonate reservoir. The reservoir is a thick carbonate, which will flow commercial oil with a sufficient fracture network. Extensive calibration data include (1) a horizontal borehole’s resistivity image log, (2) the first 24 months cumulative oil produced, by stage, as known from chemical frac tracer data, (3) pre- and postfrac job instantaneous shut-in pressures, (4) microseismic, and (5) wireline log data. We used the cumulative oil production to document the spatially varying amount of aligned vertical porosity (aligned compliance or fracture porosity) connected to the stage borehole location. The stages of high oil production exhibited, for the fracture-perpendicular azimuth, the more positive amplitude variation with angle (AVA) gradients, and dimmer near-angle (6°–15° angles of incidence) amplitudes, compared to the fracture-parallel azimuth. The azimuthal variation of the AVA gradient fit the cos 2θ curve well, indicating the presence of one set of vertical aligned fractures dominating the azimuthal amplitude signature. In a similar fashion, the azimuthal variation of the mathematical intercept, physically the near-angle amplitudes, also fit the cos 2θ curve well. We have constructed crossplots of the azimuthal near-angle amplitude versus the AVA gradient on a bin-by-bin basis: we observed a straight line at bins with elevated oil production (elevated fracture density). A straight line crossplot of the (AVA gradient, mathematical intercept) is the signature of change of the (sensed) porosity, as long as the lithology and pore fluid are held constant. In accord with industry knowledge, we found that porosity affects the P impedance and thus the near-angle amplitudes: the aligned porosity yields azimuthal P impedance (measured at the 6°–15° angles of incidence). Legacy high-fold 3D P-P surveys rich in the 6°–20° angles of incidence should be considered for reprocessing and reinterpretation using these techniques.

Hydromechanical insight of fracture opening and closure during in-situ hydraulic fracturing in crystalline rock

Six hydraulic fracturing (HF) experiments were conducted in situ at the Grimsel Test Site (GTS), Switzerland, using two boreholes drilled in sparsely fractured crystalline rock. High spatial and temporal resolution monitoring of fracture fluid pressure and strain improve our understanding of fracturing dynamics during and directly following high-pressure fluid injection. In three out of the six experiments, a shear-thinning fluid with an initial static viscosity approximately 30 times higher than water was used to understand the importance of fracture leak-off better. Diagnostic analyses of the shut-in phases were used to determine the minimum principal stress magnitude for the fracture closure cycles, yielding an estimate of the effective instantaneous shut-in pressure (effective ISIP) 4.49±0.22 MPa. The jacking pressure of the hydraulic fracture was measured during the pressure-controlled step-test. A new method was developed using the uniaxial Fibre-Bragg Grating strain signals to estimate the jacking pressure, which agrees with the traditional flow versus pressure method. The technique has the advantage of observing the behavior of natural fractures next to the injection interval. The experiments can be divided into two groups depending on the injection location (i.e., South or North to a brittle-ductile S3 shear zone). The experiments executed South of this zone have a jacking pressure above the effective ISIP. The proximity to the S3 shear zone and the complex geological structure led to near-wellbore tortuosity and heterogeneous stress effects masking the jacking pressure. In comparison, the experiments North of the S3 shear zone has a jacking pressure below the effective ISIP. This is an effect related to shear dislocation and fracture opening. Both processes can occur almost synchronously and provide new insights into the complicated mixed-mode deformation processes triggered by high-pressure injection.

Automated pressure transient analysis: A cloud-based approach

Pressure transient analysis provides essential information to evaluate the dimensions of injection induced fractures, permeability damage near the wellbore, and pressure elevation in the injection horizon. For injection wells, shut-in data can be collected and analyzed after each injection cycle to evaluate the well injectivity and predict the well longevity. However, any interactive analysis of the pressure data could be subjective and time-consuming. In this study a novel cloud-based approach to automatically analyzing pressure data is presented, which aims to improve the reliability and efficiency of pressure transient analysis.There are two fundamental requirements for automated pressure transient analysis: 1) Pressure data needs to be automatically retrieved from field sites and fed to the analyzer; 2) The engineer can automatically select instantaneous shut-in pressure (ISIP), identify flow regimes, and determine the fracture closure point if any. To meet these requirements as well as to take advantage of cloud storage and computing technologies, a web-based application has been developed to pull real time injection data from any field sites and push it to a cloud database. A built-in pressure transient workflow has been also proposed to detect any stored or real-time pressure data and perform pressure analysis automatically if the required data is available.The automated pressure transient analysis technology has been applied to multiple injection projects. In general, the analysis results including formation and fracture properties (i.e. permeability, fracture half length, skin factor, and fracture closure pressure) are comparable to results from interactive analysis. Any discrepancies are mainly caused by poor data quality. Issues such as inconsistent selections of ISIP and different slopes defined for pre and after closure analyses also contribute to the divergence. Overall, the automated pressure transient analysis provides consistent results as the exact same criteria are applied to the pressure data, and analysis results are independent of the analyzer's experience and knowledge.As data from oil/gas industry increases exponentially over time, automated data transmission, storage, analysis and access are becoming necessary to maximize the value of the data and reduce operation cost. The automated pressure transient analysis presented here demonstrates that cloud storage and computing combined with automated analysis tools is a viable way to overcome big data challenges faced by oil/gas industry professionals.

Investigating Near-Wellbore Diversion Methods for Refracturing Horizontal Wells

Summary Near-wellbore diversion of fracturing fluid and proppant is a common approach to achieving improved treatment efficiency when refracturing horizontal wells for expanding treatment coverage within the lateral. There are five broad categories of near-wellbore diversion methods: particulate diversion for bridging open fractures connected to the wellbore; perforation sealing to limit injectivity into open perforation clusters at the wellbore; filling up the drained fracture system with water for achieving more uniform pressurization (i.e., fill-up); injection rate cycling/hesitation fracturing; and mechanical isolation by installing cemented or expandable liners in the lateral followed by plug-and-perforated stimulation. These tactics can be used standalone or combined. Particulate diverting agents can be additionally categorized by particle type (e.g., granular, fibrous) and solubility characteristics. Perforation sealing agents consist of deformable and rigid/spherical subtypes, both of which can be further categorized by solubility characteristics. In this study, treatment and production data for 72 ConocoPhillips refractured wells in a North America shale play were analyzed to evaluate the effectiveness of the various near-wellbore diversion methods and materials. An index was formulated using information on reservoir depletion to normalize changes in bottomhole fracture pressure over time. This was determined by periodically discontinuing injection to obtain instantaneous shut-in pressures (ISIPs) over the course of the treatment. The calculated indices were plotted for each type of diverting system to compare trends for gaining insight on in-situ stress buildup. Production data grouped by different diversion methods were also analyzed. The near-wellbore diversion methods included mixed-size particulates with and without fibrous materials, deformable and rigid perforation sealers, fill-up tactics in which near-wellbore diverting agents were not used, and mechanical isolation by cementing a newly installed liner in the lateral followed by plug-and-perforated stimulation. Fracture hit analysis of offset well treatments indicated that refracturing treatments using particulate diverters were heel biased with respect to reservoir repressurization. The study showed that the incremental pressure as a result of diverter landing on perforations is a poor indication of diverter efficiency. A non-normalized ISIP trend is misleading as an indicator for post-refracturing well performance. Refractured wells with either particulate diverters or perforation sealers both show initial fluid fill-up into the depleted region before the stress buildup plateaus. Wells that have liners installed and cemented inside the original wellbore and that are then restimulated with standard plug-and-perforated techniques show superior performance compared with all diversion methods used in bullhead refracturing treatments. Choice of diversion can have a significant impact on results, but not all particulate diverters or perforation sealers behave similarly. Wells refractured using only the fill-up method have long-term productivity on par with or better than wells refractured with most types of diverting agents.

Fracturing curve and its corresponding gas productivity of coalbed methane wells in the Zhengzhuang block, southern Qinshui Basin, North China

Hydraulic fracturing has been widely used in low permeability coalbed methane reservoirs to enhance gas production. To better evaluate the hydraulic fracturing curve and its effect on gas productivity, geological and engineering data of 265 development coalbed methane wells and 14 appraisal coalbed methane wells in the Zhengzhuang block were investigated. Based on the regional geologic research and statistical analysis, the microseismic monitoring results, in-situ stress parameters, and gas productivity were synthetically evaluated. The results show that hydraulic fracturing curves can be divided into four types (descending type, stable type, wavy type, and ascending type) according to the fracturing pressure and fracture morphology, and the distributions of different type curves have direct relationship with geological structure. The vertical in-situ stress is greater than the closure stress in the Zhengzhuang block, but there is anomaly in the aggregation areas of the wavy and ascending fracturing curves, which is the main reason for the development of multi-directional propagated fractures. The fracture azimuth is consistent with the regional maximum principle in-situ stress direction (NE–NEE direction). Furthermore, the 265 fracturing curves indicate that the coalbed methane wells owned descending, and stable-type fracturing curves possibly have better fracturing effect considering the propagation pressure gradient (FP) and instantaneous shut-in pressure (PISI). Two fracturing-productivity patterns are summarized according to 61 continuous production wells with different fracturing type and their plane distribution, which indicates that the fracturing effect of different fracturing curve follows the pattern: descending type > stable type > wavy type > ascending type.

Application of Discrete Fracture Network Model in the Simulation of Massive Fracturing in Tight Oil Reservoir

Massive fracturing technology can form a complex fracture network and a large drainage area by multi-stage/multi-cluster perforation and injection of low viscosity fluids such as silckwater.the traditional bi-wing planar model is not applicable in the simulation of massive fracturing, and a new network model is needed. The pseudo-three-dimension (P3D) Discrete Fracture Network (DFN) model are based on self-similar solution methodology, and the fracture characteristics are then calculated numerically. we performed a comparison between DFN model and Cluster Facture model through the integration of rock mechanics, well logging and micro seismic detection technology. After the mini-fracture analysis and closure analysis, parameters like instantaneous shut-in pressure (ISIP), closure pressure and reservoir permeability were obtained. Based on these parameters, pressure history match and SRV match were performed, the result shows that DFN model works better than the Cluster Fracture model in the matching. The research proves the feasibility of DFN model in the simulation of massive fracturing in tight oil reservoirs.

Consistent Model for Injection and Falloff Pressure Match of Diagnostic Fracture Injection Tests (DFITs)

Summary The diagnostic fracture injection test (DFIT), a fracture–injection/falloff test, is a reliable tool for quantifying the formation of closure stress, leakoff coefficient, formation permeability, and pressure. The current analytical DFIT model (used before and after closure) enables one to match the pressure falloff of abnormal leakoff behaviors, and quantifies more formation parameters than a traditional DFIT model. However, this model design addresses only the falloff data after shut–in; thus, analysts have expressed concerns that the net pressure implied by the falloff is inconsistent with the injection pressure behavior. Therefore, this paper provides a model capable of matching both injection and falloff pressure behaviors. The pressure–falloff model is capable of quantifying essential pressure values including, in order of occurrence, instantaneous shut–in pressure (ISIP), minimum fracture–propagation pressure, one or more closure–stress values, formation minimum principal stress, and pore pressure. The early pressure response represents the dissipation of three kinds of friction—wellbore, perforation, and near–wellbore friction. Each of them is quantified, and, together, they comprise the difference between the pressure at the end of injection and the ISIP. Presence of tip extension enables the quantification of the minimum fracture–propagation pressure. The minimum principal stress is consistent with the final closure stress. Subtracting the closure stress and friction pressure losses from the recorded or calculated bottomhole pressure (BHP) provides the fracture net pressure. The model match for injection pressure behavior incorporates the same pressures and consistent values for 2D fracture geometry and leakoff coefficient. The global match confirms not only the estimation of formation and fracture properties from the pressure–falloff analysis, but also the friction losses along the wellbore, through the perforations, and in the near–wellbore tortuosity during and after injection. In particular, by matching both injection and falloff, the model incorporates friction pressure losses that can explain apparent excessive net pressure. The match with both injection and falloff pressure variation addresses concerns that the net pressure implied by the falloff model match cannot be consistent with the observed injection behavior. When the pressure difference between the final DFIT pick for closure stress and the pressure at the end of injection is large, the reason might be tip extension and/or large friction pressure losses, the latter of which can be addressed by the main treatment design.

Development of an Empirical Equation To Predict Hydraulic-Fracture Closure Pressure From the Instantaneous Shut-In Pressure Using Subsurface Solids-Injection Data

Summary During hydraulic-fracturing operations, conventional pressure-falloff analyses (G-function, square root of time, and other diagnostic plots) are the main methods for estimating fracture-closure pressure. However, there are situations when it is not practical to determine the fracture-closure pressure using these analyses. These conditions occur when closure time is long, such as in mini-fracture tests in very tight formations, or in slurry-waste-injection applications where the injected waste forms impermeable filter cake on the fracture faces that delays fracture closure because of slower liquid leakoff into the formation. In these situations, applying the conventional analyses could require several days of well shut-in to collect enough pressure-falloff data during which the fracture closure can be detected. The objective of the present study is to attempt to correlate the fracture-closure pressure to the early-time falloff data using the field-measured instantaneous shut-in pressure (ISIP) and the petrophysical/mechanical properties of the injection formation. A study of the injection-pressure history of many injection wells with multiple hydraulic fractures in a variety of rock lithologies shows a relationship between the fracture-closure pressure and the ISIP. An empirical equation is proposed in this study to calculate the fracture-closure pressure as a function of the ISIP and the injection-formation rock properties. Such rock properties include formation permeability, formation porosity, initial pore pressure, overburden stress, formation Poisson's ratio, and Young's modulus. The empirical equation was developed using data obtained from geomechanical models and the core analysis of a wide range of injection horizons with different lithology types of sandstone, carbonate, and tight sandstone. The empirical equation was validated using different case studies by comparing the measured fracture-closure-pressure values with those predicted by using the developed empirical equation. In all cases, the new method predicted the fracture-closure pressure with a relative error of less than 6%. The new empirical equation predicts the fracture-closure pressure using a single point of falloff-pressure data, the ISIP, without the need to conduct a conventional fracture-closure analysis. This allows the operator to avoid having to collect pressure data between shut-in and the time when the actual fracture closure occurs, which can take several days in highly damaged and/or very tight formations. Moreover, in operations with multiple-batch injection events into the same interval/perforations, as is often the case in cuttings/slurry-injection operations, the trends in closure-pressure evolution can be tracked even if the fracture is never allowed to close.